U.S. patent application number 16/416944 was filed with the patent office on 2019-11-21 for gas lift optimization process.
The applicant listed for this patent is PCS FERGUSON, INC.. Invention is credited to DUSTIN LEVI SANDIDGE.
Application Number | 20190353016 16/416944 |
Document ID | / |
Family ID | 68534258 |
Filed Date | 2019-11-21 |
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United States Patent
Application |
20190353016 |
Kind Code |
A1 |
SANDIDGE; DUSTIN LEVI |
November 21, 2019 |
GAS LIFT OPTIMIZATION PROCESS
Abstract
A system, method and process (utility) is presented to control a
gas injection setpoint of a production well utilizing gas lift. The
utility may control a flow valve and/or source of injection gas
(e.g., gas injection compressor) to increase or decrease a gas
injection flow rate (e.g., setpoint) into the well during a gas
injection interval. The utility monitors bottom hole pressure
related values for multiple gas injection intervals with each have
different gas injection setpoints (e.g., flow volumes). Bottom Hole
Pressures (e.g., averages). The differences between the Bottom Hole
Pressures are compared to calculate Bottom Hole Pressure Drawdown
(BHPD) rates between intervals. A subsequent gas injection setpoint
(e.g., direction and/or magnitude of change) is selected based on a
comparison of a current BHPD and a previous BHPD.
Inventors: |
SANDIDGE; DUSTIN LEVI; (DE
BEQUE, CO) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
PCS FERGUSON, INC. |
Frederick |
CO |
US |
|
|
Family ID: |
68534258 |
Appl. No.: |
16/416944 |
Filed: |
May 20, 2019 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
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62674160 |
May 21, 2018 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 47/10 20130101;
E21B 43/122 20130101; E21B 47/06 20130101; E21B 43/123
20130101 |
International
Class: |
E21B 43/12 20060101
E21B043/12; E21B 47/06 20060101 E21B047/06; E21B 47/10 20060101
E21B047/10 |
Claims
1. A process for adjusting a gas injection setpoint for a well
utilizing gas lift, comprising: identifying a first Bottom Hole
Pressure Drawdown (BHPD) between an end of a first gas injection
interval having a first gas injection setpoint and an end of a
second gas injection interval having a second gas injection
setpoint; identifying a second BHPD between an end of a third gas
injection interval having a third gas injection setpoint and the
end of the second gas injection interval; comparing the second BHPD
to the first BHPD; and adjusting a gas injection setpoint for a
subsequent gas injection interval based on the comparison.
2. The process of claim 1, further comprising: maintaining gas flow
into a well at the first gas injection setpoint for the first gas
injection interval to establish a first bottom hole pressure (BHP)
at the end of the first gas injection interval; maintaining gas
flow into the well at the second gas injection setpoint for the
second gas injection interval to establish a second BHP at the end
of the second gas injection interval; and identifying a change
between the first BHP and the second BHP, wherein the change
corresponds to the first BHPD.
3. The process of claim 2, further comprising: maintaining gas flow
into the well at the third gas injection setpoint for the third gas
injection interval to establish a third BHP at the end of the third
gas injection interval; and identifying a change between the second
BHP and the third BHP, wherein the change corresponds to the second
BHPD.
4. The process of claim 3, wherein the establishing of each BHP
comprises at least one of: obtaining a bottom hole pressure
measurement from a bottom hole pressure sensor; obtaining a bottom
hole pressure related value from an output of a production flow
sensor; and generating a bottom hole pressure related value from a
multiphase correlation calculation.
5. The process of claim 3, wherein establishing each BHP comprises:
generating an average BHP for each gas injection interval.
6. The process of claim 3, further comprising for each gas
injection interval: monitoring a current gas flow into the well;
comparing the gas flow to a predetermined minimum gas flow; and
suspending the gas injection interval when the current gas flow
into the well is less that the predetermined minimum gas flow.
7. The process of claim 6, further comprising: identifying when the
current gas flow exceeds the gas injection setpoint for the gas
injection interval; and restarting the gas injection interval.
8. The process of claim 1, wherein adjusting the gas injection
setpoint for the subsequent interval based on the comparison,
further comprises: adjusting the gas injection setpoint for the
subsequent interval in the direction of a previous gas injection
setpoint adjustment if the second BHPD is greater than the first
BHPD adjusting the gas injection setpoint for the subsequent
interval in a direction opposite of the previous gas injection
setpoint adjustment if the second BHPD is less than the first
BHPD.
9. The process of claim 8, wherein the adjusting of the gas
injection setpoint for the subsequent interval comprises one of
increasing the gas injection setpoint for the subsequent interval
and decreasing the gas injection setpoint for the subsequent
interval.
10. The process of claim 8, wherein adjusting the gas injection
setpoint for the subsequent interval in a direction opposite of the
previous gas injection setpoint adjustment comprises: adjusting the
gas injection setpoint in the opposite direction with a magnitude
that is a fraction of a magnitude of the previous gas injection
setpoint adjustment.
11. The process of claim 1, further comprising: comparing the
second BHPD to a predetermined threshold; and increasing the gas
injection setpoint for the subsequent gas injection interval if the
second BHPD is less than the predetermined threshold.
12. A system for adjusting a gas injection setpoint for a well
utilizing gas lift, comprising: a flow control valve disposed in a
flow path between a gas source and a well; a flow meter disposed in
the flow path between the gas source and the well, the flow meter
being configured to measure a rate of gas flow through the flow
path and generate a corresponding output; a controller in
communication with the flow control valve and the flow meter, the
controller configured to: adjust the flow control valve to
establish gas injection setpoints for gas injection intervals,
respectively; identify a Bottom Hole Pressure (BHP) for each gas
injection interval; calculate a current Bottom Hole Pressure
Drawdown (BHPD) between an end of a current gas injection interval
and an end of a previous gas injection interval; compare the
current BHPD to a previous BHPD; calculate an adjusted gas
injection setpoint for a subsequent gas injection interval based on
the comparison; and generate a valve control signal for receipt by
the flow control valve, the flow control valve being configured to
adjust a rate of gas flow into a well to the adjusted gas injection
setpoint in response to a valve control signal.
13. The system of claim 12, further comprising at least one of: a
bottom hole pressure sensor connected to the controller, wherein
the controller identifies the BHP based on an output of the bottom
hole pressure sensor; and a production flow sensor connected to the
controller, wherein the controller identifies the BHP based on an
output of the production flow sensor.
14. The system of claim 12, wherein the controller is configured to
perform a multiphase correlation calculation, wherein the
controller identifies the BHP based on an output of the multiphase
correlation calculation.
15. The system of claim 12, wherein the controller is configured
to: identify a change between a BHP for the current gas injection
interval and a BHP for an immediately previous gas injection
interval, wherein the change is the current BHPD.
16. The system of claim 15, wherein the controller is configured
to: set the adjusted gas injection setpoint for the subsequent
interval in the direction of a previous gas injection setpoint
adjustment if the current BHPD is greater than the previous BHPD;
and set the adjusted gas injection setpoint for the subsequent
interval in a direction opposite of the previous gas injection
setpoint adjustment if the current BHPD is less than the previous
BHPD.
17. The system of claim 16, wherein the controller is configured
to: increasing the previous the gas injection setpoint or decrease
the previous gas injection setpoint for the subsequent
interval.
18. The process of claim 16, wherein, when setting the adjusted gas
injection setpoint in a direction opposite of the previous gas
injection setpoint adjustment, the controller is configured to: set
the adjusted gas injection setpoint in the opposite direction with
a magnitude that is a fraction of a magnitude of the previous gas
injection setpoint adjustment.
19. A process for adjusting a gas injection setpoint for a well
utilizing gas lift, comprising: calculating a current Bottom Hole
Pressure Drawdown (BHPD) between an end of a current gas injection
interval and an end of a previous gas injection interval; comparing
the current BHPD to a previous BHPD; calculating an adjusted gas
injection setpoint for a subsequent gas injection interval based on
the comparison; and controlling flow control valve disposed in a
flow path between a gas source and the well to adjust a rate of gas
flow into the well to the adjusted gas injection setpoint.
20. The process of claim 19, further comprising: identifying a
Bottom Hole Pressure (BHP) for the current gas injection interval;
identifying a change between the current BHP and a previous BHP for
a previous gas injection interval, wherein the change represents
the BHPD.
21. The process of claim 19, further comprising: setting the
adjusted gas injection setpoint for the subsequent interval in the
direction of a previous gas injection setpoint adjustment if the
current BHPD is greater than the previous BHPD; and setting the
adjusted gas injection setpoint for the subsequent interval in a
direction opposite of the previous gas injection setpoint
adjustment if the current BHPD is less than the previous BHPD.
22. The process of claim 21, further comprising: setting the
adjusted gas injection setpoint in the opposite direction with a
magnitude that is a fraction of a magnitude of the previous gas
injection setpoint adjustment.
Description
CROSS REFERENCE
[0001] The present application claims the benefit of the filing
date of U.S. Provisional Application No. 62/674,160 having a filing
date of May 21, 2018, the entire contents of which is incorporated
herein by reference.
FIELD
[0002] The present disclosure relates to artificial lift systems
that inject gas into production tubing of hydrocarbon production
wells. More specifically, a process is provided that allows for
dynamically adjusting (e.g., increase or decrease) a gas injection
rate to identify a rate that yields a near peak bottom hole
pressure drawdown and/or total fluid production.
BACKGROUND
[0003] Well bores of oil and gas wells extend from the surface to
permeable subterranean formations (`reservoirs`) containing
hydrocarbons. These well bores are drilled in the ground to a
desired depth and may include horizontal sections as well as
vertical sections. In any arrangement, piping (e.g., steel), known
as casing, is inserted into the well bore. The casing may have
differing diameters at different intervals within the well bore and
these various intervals of casing may be cemented in-place. Other
portions (e.g., within producing formations) may not be cemented in
place and/or include perforations to allow hydrocarbons to enter
into the casing. Alternatively, the casing may not extend into the
production formation (e.g., open-hole completion).
[0004] Disposed within a well casing is a string of production
piping/tubing, which has a diameter that is less than the diameter
of the well casing. The production tubing may be secured within the
well casing via one or more packers, which may provide a seal
between the outside of the production piping and the inside of the
well casing. The production tubing provides a continuous bore from
the production zone to the wellhead through which oil and gas can
be produced.
[0005] The flow of fluids, from the reservoir(s) to the surface,
may be facilitated by the accumulated energy within the reservoir
itself, that is, without reliance on an external energy source. In
such an arrangement, the well is said to be flowing naturally. When
an external source of energy is required to flow fluids to the
surface the well is said to produce by a means of artificial
lifting. Generally, this is achieved by the use of a mechanical
device inside the well (e.g., pump) or by decreasing the weight of
the hydrostatic column in the production tubing by injecting gas
into the liquid some distance down the well.
[0006] The injection of gas to decrease the weight of a hydrostatic
column is commonly referred to as gas lift, which is artificial
lift technique where bubbles of compressed air/gas are injected to
reduce the hydrostatic pressure within the production tubing to
below a pressure at the inlet of the production tubing. In one gas
lift arrangement, high pressure gas is injected into the annular
space between the well casing and the production tubing. At one or
more predetermined locations along the length of the production
tubing, gas lift valves permit the gas in the annular space to
enter into the production tubing. Such a gas lift artificial lift
system may be combined with additional artificial lift systems. For
instance, gas lift may be combined with plunger lift in some
arrangements.
SUMMARY
[0007] Presented herein are systems, methods and processes (i.e.,
utilities) for enhancing or optimizing the gas injection setpoint
of a well utilizing gas lift. Generally, the utilities includes
initiating a gas lift at an initial gas injection rate or setpoint.
The utility utilizes inputs associated a bottom hole pressure to
subsequently adjust the gas injection rate. Such inputs may be
acquired from, for example, a bottom hole pressure sensor and/or a
production rate sensor. In the former regard, a dedicated bottom
hole pressure sensor monitors a bottom hole pressure drawdown rate.
In the latter regard, a production rate sensor allows for
substituting the bottom hole pressure with a total fluid production
rate. In further embodiments, the bottom hole pressure may be
inferred. For instance, when a dedicated sensor is not available to
monitor (e.g., directly or indirectly) bottom hole pressure, the
bottom hole pressure may be inferred from known well data and one
or more variables (e.g., well depth, formation depth, casing size,
temperature etc.) that are known or may be measured. By way of
example, performance of a multiphase correlation calculation may
provide an input associated with a down hole pressure. Various
multiphase correlations are known including, without limitation,
Hagedorn and Brown, Petroleum Experts, Petroleum Experts 2,
Petroleum Experts 3, Fancher Brown, and Beggs and Brill, to name a
few.
[0008] In any arrangement, the utilities control a gas injection
flow valve and/or source of injection gas (e.g., gas injection
compressor) to increase or decrease a gas injection flow rate into
the well during a gas injection interval. In an arrangement, an
initial injection rate (e.g., gas injection setpoint) is maintained
for a predetermined interval. Based on this injection rate an
initial bottom hole pressure (e.g., first BHP) is determined for
the interval. The gas injection rate or setpoint is then either
increased or decreased a predetermined amount for another time gas
injection interval. A subsequent average bottom hole pressure is
obtained (e.g., second BHP). At the initiation of the process, the
gas injection rate is then increased or decreased in the same
direction as the previous increase or decrease for another gas
injection interval to find a further bottom hole pressure (e.g.,
third BHP). The difference or change between the first BHP and
second BHP is compared with difference of change between the second
BHP and the third BHP. This changes correspond to a Bottom Hole
Pressure Drawdown (BHPD) rate. If the second drawdown rate is
greater than the first drawdown rate, the direction of change in
the injection rate is trending toward a more optimal setting and
further increases or decreases in the same direction are applied to
the gas injection rate. If the second drawdown rate is less that
the first drawdown rate, the injection rate is being adjusted in
the incorrect direction and the process reverses. The process may
continue in a loop further adjusting the gas injection rate to
iterate to closer an optimal setting. That is, after initiation of
the process, a new or subsequent BHPD is compared to the
prior/previous BHPD to determine a subsequent adjustment direction
and/or magnitude for a subsequent gas injection rate. However, in
various arrangements, the process may be interrupted and/or altered
based on one or more predetermined factors.
BRIEF DESCRIPTION OF THE FIGURES
[0009] FIG. 1 is a graph showing well decline over time.
[0010] FIGS. 2A-2C illustrate gas injection values in a gas lift
artificial lift system.
[0011] FIG. 3 illustrates a graph of a gas injection rate versus
Bottom Hole Pressure (BHP) for any given point in time.
[0012] FIG. 4 illustrates a graph of gas injection rates versus
Bottom Hole Pressure drawdown.
[0013] FIG. 5 illustrates a system for adjusting gas injection
setpoints at a production well including gas lift artificial
lift.
[0014] FIG. 6 illustrates one process for adjusting gas injection
setpoints.
[0015] FIG. 7 illustrates a graph of gas injection rate adjustments
and changes in Bottom Hole Pressure.
[0016] FIG. 8 illustrates a graph of gas injection rates relative
to an optimal gas injection rate.
[0017] FIG. 9 illustrates another process for adjusting gas
injection setpoints.
[0018] FIG. 10 illustrates a process for monitoring available
injection gas for use in adjusting gas injection setpoints.
DETAILED DESCRIPTION
[0019] Reference will now be made to the accompanying drawings,
which at least assist in illustrating the various pertinent
features of the present disclosure. The following description is
presented for purposes of illustration and description and is not
intended to limit the disclosed embodiments to the forms disclosed
herein. Consequently, variations and modifications commensurate
with the following teachings, and skill and knowledge of the
relevant art, are within the scope of the present disclosure.
Definition of Terms
[0020] Control valve--An electronic actuating valve that moves open
and close based on an external input
[0021] Bottom Hole Pressure (BHP)--A pressure value that is
indicative of a pressure at the bottom of a well.
[0022] Gas injection setpoint--Gas injection rate into an well
bore.
[0023] Optimal Gas injection Setpoint--Gas injection rate that
yields the greatest BHP drawdown or total fluid production.
[0024] Unloading--Increasing Gas Injection that produces a higher
BHP delta
[0025] Loading--Decreasing Gas injection that produces a lower BHP
delta
[0026] Drawdown--Decreasing Gas injection to produce a higher BHP
delta
[0027] Build Up--Increasing Gas injection that produces a lower BHP
delta
[0028] The following disclosure is directed to a process for
optimizing a gas injection rate to maximize total fluid production
of a well, which typically corresponds to the maximized bottom hole
drawdown.
[0029] After being drilled and completed, well production typically
declines over time. This decline can be defined as depleting gas
and fluid production rates which are directly related to the
reduction in reservoir pressure. FIG. 1 shows a general well
decline (e.g., decline curve) over time. The well typically
declines at different rates .DELTA.P1-.DELTA.P3 at various times in
the wells life. The well, at some point, will require some form of
artificial lift to improve production by supplementing energy to
the wellbore. One form of artificial lift is gas lift.
[0030] FIG. 2A is a schematic illustration of an exemplary
installation of a conventional gas lift arrangement. As
illustrated, a string of production tubing 12 is disposed within a
casing 10 of an oil and gas well. Disposed along the production
string 12 at predetermined subterranean locations are one or more
mandrels 20. Each of these mandrels 20 supports a gas lift valve
22, which is operative to open and close based on pre-set pressure
settings. As shown in FIG. 2B, each mandrel 20 is tubular member
having first and second open-ends 24, 26 that are adapted for
in-line connection with the production tubing 12. In this regard,
one or both ends may be threaded and/or include a collar. The
mandrel 20 further includes a lug 28 on its outside surface that
supports the gas lift valve 22. The lug includes one or more
internal valve ports/bleed ports 18 that communicate with the
interior of the mandrel. See FIG. 2C. The gas lift valve 22 may be
any appropriately configured gas lift valve and may include various
check valves. Typically, such gas lift valves include internally
pressurized bellows that allow the valve to open and close based on
predetermined pressure changes. For instance, such valves may
normally be closed and only open after a gas lift pressure
overcomes a downward force of the charged bellows. Exemplary valves
are available from PCS Ferguson, Inc. of 3771 Eureka Way,
Frederick, Colo. 80516.
[0031] In operation, a high-pressure source of gas (not shown) is
injected into the well casing in the annulus between the
well-casing 10 and the production tubing 12. The gas lift valves 22
supported by each mandrel 20 opens as the injection gas displaces
fluid from the annulus. As these valves open, the opened valve
injects gas from the annulus into production tubing 12 via valve
port(s) 18 in the mandrel 20. See FIG. 2C. In some arrangements,
upper gas valves may close after lower gas valves open. In any
arrangement, as the injected gas flows to the surface it expands
thereby lifting the liquid within the production tubing and
reducing the density and column weight of the fluid in the tubing.
It will be appreciated that the gas lift arrangement may be
combined with additional artificial lift systems. For instance, the
gas lift arrangement may be paired with plunger lift. In such an
arrangement (not shown), a plunger may be disposed within the
production tubing. Such a plunger may cycle between to bottom of
the well and the top of the well to facilitate removal of liquids
from the well.
[0032] Aspects of the present disclosure are directed to adjusting
the rate at which pressurized gas is injected into the well in the
annulus in the annulus between the well-casing and the production
tubing. When using gas gift as a means of artificial lift, the Gas
Injection Rate (GIR) is a key contributor to successful producing
of the well. As noted, gas is compressed and injected through a
series of valves such that the gas enters the production tubing
along with reservoir fluids and formation gas. FIG. 3 illustrates a
graph of a gas injection rate versus Bottom Hole Pressure (BHP) for
any given point in time. Generally, it is desirable to minimize the
BHP, which allows reservoir fluids and formation gases to more
readily enter the production tubing of the well. As shown by the
graph, if a Gas Injection Rate (i.e., x-axis) is lower than
optimal, liquids may accumulate in the bottom of the well bore.
That is, under injection may result in liquid loading of the well
which may increase the BHP. Likewise, such liquid accumulation may
reduce fluid production. More broadly, under injection may result
in a failure of the BHP to drop or may actually increase the BHP in
some cases depending on where the well is on its decline curve. If
the Gas Injection Rate is too high, then the volume of gas injected
into the production tubing may reduce the area within the
production tubing that reservoir fluids and formation gases could
otherwise occupy to come to the surface. This scenario may also
reduce fluid production and increase the BHP due to, for example,
pressure build up within the production tubing. As illustrated in
FIG. 3, both under injection and over injection can result in an
increase in bottom hole pressure, which reduces the efficiency of
the well.
[0033] FIG. 3 also illustrates the recognition that, at any point
in time over the natural decline curve of a well, an optimal gas
injection rate can be identified by seeking the maximum BHP
drawdown rate. FIG. 3 also illustrates that if a current gas
injection rate is too low the gas injection must be increased to
optimize production and increase bottom hole pressure drawdown.
Likewise, FIG. 3 illustrates that if a current gas injection rate
is too high then gas injection must be reduced to optimize
production and increase bottom hole pressure drawdown.
[0034] The present disclosure is directed to determining a near
optimal gas injection rate that will result in reducing a bottom
hole pressure and/or enhancing the rate of bottom hole pressure
drawdown. By monitoring or otherwise estimating a bottom hole
pressure based on available data, a near optimal gas injection rate
may be iteratively determined by increasing or decreasing gas
injection rates to determine which injection rate yields the
greatest rate of reduction of the bottom hole pressure (e.g.,
Bottom Hole Pressure Drawdown or BHPD). By tracking the different
injection rates (e.g., injection rate setpoints) and comparing the
results for each injection rate setpoint to previous injection rate
setpoints, a trend can be developed which will indicate whether the
current injection rate setpoint is above or below an optimal gas
injection rate. Accordingly, the current injection rate setpoint
may be adjusted to be nearer the optimal gas injection rate.
[0035] A practical example of the concepts shown in FIG. 1 and FIG.
3 can be seen in FIG. 4. Over the course of a 30 day well test,
three different gas injection rates (e.g., gas injection rate
setpoints or `GIR` were tested to determine which rate created the
greatest decline in BHP. The slope of the decline was monitored,
and it was determined that setpoint 2 (GIR2; 450 MCF) produced the
steepest decline in BHP. Setpoints 1 (GIR1; 350 MCF) and 3 (GIR3;
550 MCF) did not produce a decline rate that was as steep as the
decline rate of setpoint 2 (GIR2; 450 MCF) so these setpoints would
not be considered optimal. The injection setpoint optimization
process, which is discussed herein, automates this well testing
process to constantly hunt for a near optimal gas injection rate
while monitoring and tracking the changes in BHP.
[0036] The automated process (e.g., hunting process) of determining
a near optimal gas injection rate uses several different inputs
that are subsequently ran through a calculation to determine what
the next output (i.e., gas injection rate setpoint) will be to
eventually determine a near optimal gas injection setpoint. The
hunting process is executed in an electronic controller\RTU\PLC or
other processing device. The configuration, status, and results of
the process may be made available to a remote terminal via a
communications connection (e.g., via wireline or wireless
communications) where an operator can review the data.
Modifications to the configuration may be made remotely through the
same connection.
[0037] FIG. 5 illustrates one embodiment of a production well
incorporating equipment to implement the hunting process. As
illustrated, a well head assembly 8 (e.g., a lubricator assembly)
is disposed on the surface above a well bore having a casing string
10 and production tubing 12. In some embodiments, the well head
assembly 8 contains a plunger auto catching device. However, this
is not a requirement. The production tubing 12 includes multiple
gas injection valves 22 along its length. In the illustrated
embodiment, a gas injection line 30 connects the well bore to a gas
source to allow injecting gas in the annulus between the casing
string 10 and production tubing 12. As discussed above, this gas
may pass through the gas injection valves and into the interior of
the production tubing to lift production fluids to the surface.
[0038] Surface control equipment includes a master valve(s) 14 and
a production line 16. The master valve 14 allows for opening and
closing the well. In an embodiment, the master valve may operate in
response to instructions from a well controller 40. The controller
may operate the well based on time, pressure or based on
operator-determined requirements for production. Alternatively, the
controller may fully automate the production process. In the
illustrated embodiment, the surface control equipment also includes
the gas injection line 30, a gas injection control valve 32, a gas
injection flow meter 34 and a source of injection gas. In the
present embodiment, the source of injection gas is a compressor 36,
which may compress available production gases (e.g., pipeline
gases) in fluid connection (not shown) with the compressor. The gas
injection flow valve 32 may be any electronic actuating valve that
moves open and close based on an external input (e.g., valve
control signal from the controller 40).
[0039] The controller 40, in the illustrated embodiment, is in data
communication with either or both a bottom hole pressure gauge 42
and a production flow sensor 44. Information from these sensing
devices may be used as an input in the hunting process. In this
regard, the bottom hole pressure gauge 42 and/or the production
flow sensor may generate an output that is indicative of a bottom
hole pressure of the well. These outputs may be used to monitor
bottom hole pressure drawdown for gas injection rate adjustment.
However, it will be appreciated, that the bottom hole pressure may
be otherwise measured or inferred. For instance, when a dedicated
sensor is not available to monitor bottom hole pressure, the bottom
hole pressure may be inferred from known well data and one or more
variables (e.g., well depth, formation depth, casing size,
temperature etc.) that are known to the controller and/or measured.
By way of example, performance of a multiphase correlation
calculation may provide an input associated with a down hole
pressure. Various multiphase correlations are known including,
without limitation, Hagedorn and Brown, Petroleum Experts,
Petroleum Experts 2, Petroleum Experts 3, Fancher Brown, and Beggs
and Brill, to name a few. Further, the controller 40 is in
communication with the gas injection flow meter 34 to determine the
rate that gas is being injected into the well (gas injection rate).
The flow meter may be any electronic device that measures gas
flow/volumes. In an embodiment, the flow meter measures gas flow
through an orifice. The gas injection rate forms an input for the
hunting process. The controller is also in communication with the
gas injection control valve 32. The controller generates an output
that adjusts the valve 32 to increase or decrease the gas injection
flow (e.g., flow rate) into the well.
[0040] The controller 40 can include or perform functionality of
the hunting process in addition to controlling the various valve
and equipment at the well head. Alternatively, these function may
be distributed between two or more controllers or processing
platforms (not shown). Generally, the controller 40 may include
various hardware elements and software elements. The hardware
elements can include one or more processing units, one or more
input devices (e.g., a keypad, modem etc.). The controller can also
include one or more storage devices such as, by way of example,
solid-state storage devices, random access memory (RAM) and/or a
read-only memory (ROM) etc. The controller 40 can additionally
include a communications system (e.g., a modem, a network card
(wireless or wired), an infra-red communication device, etc.), and
working memory, which can include RAM and ROM. The communications
system can permit data to be exchanged with a network and/or a
remote terminal 50. The controller 40 can also include software
elements. In some embodiments, one or more functions of the hunting
process are implemented as application code in working memory of
the controller.
[0041] FIG. 6 illustrates a flow chart of one embodiment of the
optimization hunting process 100 or hunting algorithm that may be
implemented by the controller 40. To start, an initial gas
injection rate or setpoint (e.g., a default injection rate setting
or `kick-off setting) is maintained 102 for an initial time step or
interval (e.g., hours or days) to establish a baseline or average
bottom hole pressure. In this regard, the controller 40 receives an
input from the gas injection flow meter 34 identifying the current
gas injection flow rate and generates an output to the gas
injection flow valve 32 to control adjust the gas injection rate
(e.g., gas injection rates setpoint) into the well. That is, the
system "kicks off" from a set of definable starting values (e.g.,
which may be user set) until the interval ends. At the end of the
interval, a first bottom hole average pressure (e.g., first average
BHP) is recoded/established 104 for the interval. At this time, the
interval may be reset 105 and the gas injection rate or setpoint
may be increased or decreased 106 by a predetermined amount, which
may be a maximum increase/decrease adjustment (e.g., 50 MCF). By
way of example, the initial gas injection rate or setpoint may
initially be set at 325 MCF and may be increased 50 MCF to 375 MCF.
Again, the controller may utilize information from the gas
injection flow meter 34 to control the adjustment of the gas
injection flow valve 32 to the new setpoint. This increased (or
decreased rate) is maintained 107 for the time interval (e.g.,
step) to establish 108 a second bottom hole average pressure (e.g.,
second average BHP). Once the second average BHP is established,
the time interval is reset 109 and the second average BHP is
subtracted from the first average BHP to determine 110 a current
Bottom Hole Pressure Drawdown (BHPD) (e.g., first drawdown rate).
The BHPD represents a decrease in BHP (e.g., decrease in psi) over
the time interval (e.g., hours, days weeks etc.). The gas injection
rate or setpoint is then adjusted 112 in the same direction as the
previous adjustment. Continuing the above example, the gas
injection setpoint may be increased from 375 MCF to 425 MCF.
[0042] The new gas injection setpoint is maintained 113 for another
time interval or step. After the time interval, a third bottom hole
average pressure (e.g., third average BHP) is established 114 and
the interval timer is reset 115. The third average BHP is then
subtracted from the second average BHP (i.e., the previous BHP) to
determine 116 an updated current BHPD (e.g., second drawdown rate).
A determination 118 is made regarding the change in the drawdown
rates. If the second drawdown rate is greater than the first
drawdown rate, the bottom hole pressure is continuing to decrease
and the adjustment is proceeding in the correct direction and
further adjustment is made in that direction. Continuing with the
present example, if the second drawdown rate is greater than the
first drawdown rate, the gas injection setpoint (e.g., adjusted gas
injection setpoint) is again increased 120, for example from 425
MCF to 475 MCF. In contrast, if the second drawdown is less than
the first drawdown rate, the adjustment is proceeding in the wrong
direction. In such a situation, the gas injection setpoint (e.g.,
adjusted gas injection setpoint) is decreased 122 at one-half of
the previous adjustment step. In the case of the above example, the
gas injection setpoint would decrease 25 MCF (e.g., a half
adjustment or other fractional adjustment in the opposite
direction) from 425 to 400. In either case, the loop continues for
successive time intervals/steps where a gas injection rate is
maintained 123 for a new interval and a new or current average BHP
is calculated 114 for that interval. The current average BHP is
then subtracted from the previous average BHP to establish a new or
current BHPD, which is compared to the previous BHPD such that the
gas injection rate may be further adjusted. Of note, adjustment of
the gas injection rate in the same direction as the previous
adjustment set forth above for the first two intervals is only
required at the start of the process. After a first BHPD is
established, the process may utilize any two BHPD to make
subsequent adjustments without regard to successive adjustments
being in the same direction.
[0043] The result of the hunting process set forth in FIG. 6 is
that the gas injection setpoint is increased or decreased until the
current drawdown rate is no longer larger than the previous
drawdown rate. At this time, the gas injection setpoint has passed
the optimal setpoint as shown in FIG. 3. At this time, the process
reverses the direction of gas adjustment (e.g., increase or
decrease) by half (or other fraction) of the previous step and the
process continues. In this regard, the process continues to iterate
toward the optimal setpoint using smaller adjustments to the gas
injection rate setpoint. Of note, due to changes in the well
itself, such as the decrease in production over time as illustrated
in FIG. 1, the optimal setpoint for the well likewise changes over
time. The process of FIG. 6 allows for continuing adjustment of the
gas injection setpoint in an automated process while accounting for
dynamic changes in the well itself.
[0044] FIGS. 7 and 8 illustrate thirty adjustments made to a Gas
Injection Rate setpoint for an exemplary well. More specifically,
FIG. 7 illustrates the adjustment in the GIR (i.e., GIR ADJ 210)
per interval or step along with a change in the bottom hole
pressure (i.e., BHP Delta 212) per interval or step. FIG. 8
illustrates the Gas Injection Rate-GIR 214 per interval or step,
the optimal gas injection rate (Optimal Gas Injection Rate or
Optimal Rate 216), as well as a minimum gas injection rate 218 and
a maximum gas injection rate 220. For purposes of the example, for
intervals or steps 1-14, the optimal gas injection rate is 698 MCF.
After step 14, the optimal rate increases to 845 MCF. This increase
represents, for example, a change to well conditions. For purposes
of this example, a kick-off or initial gas injection rate is 325
MFC, the maximum gas injection rate adjustment (GIR ADJ) is 50 MCF
and the first step direction is an increase in the gas injection
rate.
[0045] The graph of FIG. 7 "Delta by Step" shows the adjustments
GIR ADJ 210 made to the gas injection rate setpoint starting at the
kickoff gas injection rate as well as the change in bottom hole
pressure or BHP Delta 212 between steps. As shown, the GIR ADJ 210
is increased by the maximum (e.g., 50 MCF) for the first eight
intervals or steps. This increase is also reflected in the GIR 214
of FIG. 8 which increases from 325 MCF to 725 MCF. During these
steps, bottom hole pressure drawdown continues as the GIR 214
approaches the Optimal Gas Injection Rate 216. As shown, the GIR
214 crosses over the Optimal Gas Injection Rate 216 in Step 7 as
best shown by FIG. 8 "Gas Injection Tracking". At the point of
cross over, the magnitude of BHP Delta 212 reduces significantly in
comparison of that recorded at the previous GIR. The process then
reduces the size of the adjustment and inverts its direction to
begin hunting the Optimal Gas Injection Rate 216. As shown between
step 7 and step 13, the GIR 214 is adjusted to iterate around the
Optimal Gas Injection Rate 216. For the purposes of this example,
the Optimal Gas Injection Rate 216 increases in step 15 from 698 to
845. Accordingly, the process begins increasing the GIR 214 to hunt
for the Optimal Gas Injection Rate 216, which has increased in the
present example. The increase in the GIR ADJ 210 continues between
steps 16 and 22 as the process searches for the Optimal Gas
Injection Rate 216. At step 22, the GIR 214 again crosses the
Optimal Gas Injection Rate 214 at which time the GIR ADJ reverses
direction to continue iterating the GIR 214 about the Optimal Gas
Injection Rate 214. Table 1 illustrates mathematical data for
Example 1.
TABLE-US-00001 TABLE 1 GIR GIR BHP BHP Delta Interpretation ADJ
Kickoff 325 2100 N\A Kickoff 50 Step 1 375 2099.690402 -0.309597523
Unloading 50 Step 2 425 2099.324102 -0.366300366 Unloading 50 Step
3 475 2098.875672 -0.448430493 Unloading 50 Step 4 525 2098.297637
-0.578034682 Unloading 50 Step 5 575 2097.484629 -0.81300813
Unloading 50 Step 6 625 2096.114766 -1.369863014 Unloading 50 Step
7 675 2091.76694 -4.347826087 Unloading 50 Step 8 725 2088.063236
-3.703703704 Build Up -25 Step 9 700 2038.063236 -50 Drawdown -50
Step 10 650 2035.979903 -2.083333333 Loading 25 Step 11 675
2031.632077 -4.347826087 Unloading 50 Step 12 725 2027.928373
-3.703703704 Build Up -25 Step 13 700 1977.928373 -50 Drawdown -50
Step 14 650 1975.84504 -2.083333333 Loading 25 Step 15 675
1975.256804 -0.588235294 Build Up -12.5 Step 16 662.5 1974.708859
-0.547945205 Loading 6.25 Step 17 668.75 1974.141483 -0.567375887
Unloading 12.5 Step 18 681.25 1973.530796 -0.610687023 Unloading 25
Step 19 706.25 1972.810075 -0.720720721 Unloading 50 Step 20 756.25
1971.683315 -1.126760563 Unloading 50 Step 21 806.25 1969.10267
-2.580645161 Unloading 50 Step 22 856.25 1960.213781 -8.888888889
Unloading 50 Step 23 906.25 1958.581128 -1.632653061 Build Up -25
Step 24 881.25 1955.822507 -2.75862069 Drawdown -50 Step 25 831.25
1948.54978 -7.272727273 Drawdown -50 Step 26 781.25 1946.981152
-1.568627451 Loading 25 Step 27 806.25 1944.400507 -2.580645161
Unloading 50 Step 28 856.25 1935.511618 -8.888888889 Unloading 50
Step 29 906.25 1933.878965 -1.632653061 Build Up -25 Step 30 881.25
1931.120345 -2.75862069 Drawdown -50
[0046] The process illustrated in FIGS. 6-8 works in most instances
to drive a current Gas Injection Rate setpoint toward an Optimal
Gas Injection Rate for current well conditions. Further, the
process is dynamic in that it allows for making necessary changes
even when well conditions change over time (e.g., increase in
Optimal Rate). However, the application of the process in actual
use can encounter situations that make the process less effective.
By way of example, if the bottom hole pressure change (e.g., BHP
Delta) fails to fall sufficiently between steps/intervals or builds
between steps/intervals, reservoir pressure may be building and
remedial action may be required. By way of further example, in some
instances, insufficient gas may be available for injection.
[0047] FIG. 9 illustrates a modification to the process 100 of FIG.
6 that accounts situations where a bottom hole pressure change
fails to change sufficiently between steps/intervals. Initially,
the illustrated process 100A is substantially identical as the
process 100 of FIG. 6 and like references are utilized for like
process steps. As above, the process 100A, a kick-off gas injection
rate (GIR) is maintained 102 for an initial interval to identify or
establish a baseline or average bottom hole pressure. The interval
is then reset and the GIR may be increased or decreased 106 by a
predetermined amount. This increased (or decreased rate) is
maintained for the time interval (e.g., step) to identify or
establish 108 a second bottom hole average pressure (e.g., second
BHP). Once the second BHP is established, the second BHP is
subtracted from the first BHP to determine 110 a current Bottom
Hole Pressure Drawdown (BHPD) (e.g., first drawdown). The gas
injection rate or setpoint is then adjusted 112 in the same
direction as the previous adjustment. The new gas injection
setpoint is maintained for another time interval or step. After the
time interval, a third bottom hole average pressure (e.g., third
BHP) is identified or established 114. The third BHP is then
subtracted from the second BHP (i.e., the previous BHP) to
determine 116 an updated or current BHPD (e.g., second
drawdown).
[0048] At this point in the process 100A, a determination is made
regarding the magnitude of the current BHPD. Specifically, the
current BHPD rate is compared 124 to a predetermined threshold.
This threshold, referred to as the "Force Increase Threshold" in
FIG. 9, is a minimum drawdown rate. If the current BHPD rate is
below this threshold, it is presumed that the reservoir pressure is
increasing or at least failing to drop. Such a reservoir
increase/failure to drop is an indication that the well is
under-injected and that the well may be fluid loading, which is
undesirable. Accordingly, upon identifying such under-injection
(i.e., BHPD rate <Force Increase Threshold), the process 100A
increases 126 the gas injection rate for the next interval
regardless of the current trend. In an embodiment, this forced
increase is a maximum allowable gas rate increase. However, this is
not a requirement. It the BHPD rate is greater than the threshold,
the process 100A continues in an identical manner as the process
100 of FIG. 6.
[0049] Table 2 illustrates an exemplary set of well data wherein an
initial GIR at kickoff is 500 MCF, a Maximum GIR adjustment (GIR
ADJ) is 50 MFC and a Force Increase Threshold is 2 psi.
TABLE-US-00002 TABLE 2 BHP Step GIR BHP Delta Interpretation GIR
ADJ Kickoff 500 2100 N/A Kickoff 50 Step 1 550 2090 -10 Unloading
50 Step 2 600 2075 -15 Unloading 50 Step 3 650 2065 -10 Buildup -25
Step 4 625 2051 -14 Drawdown -50 Step 5 575 2049 -2 Loading 25 Step
6 600 2053 3 Force Increase 50 Step 7 650 2043 -10 Unloading 50
Step 8 700 2020 -23 Unloading 50
In the example of Table 2, where the Force Increase Threshold is
set as 2 psi., any change in the BHP delta that exceeds the 2 psi
threshold will result in an automatic max increase to the gas
injection setpoint regardless of the previous step adjustment
direction. As shown, at step 6, proceeding an increase of 25 MCF in
the GIR at step 5, the result was a BHP delta of 3 psi. As the BHP
in step 6 was greater than the Force Gas injection Increase
Threshold of 2 psi, the GIR adjustment to made for Step 7 is an
increase to the GIR of 50 MCH, which equivalent to the max
adjustment. Due to BHP Delta of Step 7 BHP delta being less than
the Force Increase Threshold, the normal process or algorithm
continues to run and a GIR increase is derived for Step 8 given the
BHP of Step 7 is less than both the result of Step 6 and the Force
Increase Threshold. The use of the Force Increase Threshold helps
prevent the increase in bottom hole pressure, which may reduce
production from the well.
[0050] As noted above, there may be times during production of a
well where insufficient gas may be available for injection. That
is, production gases from the well or nearby wells or pipelines are
often utilized as the source of injection gas for artificial lift.
At times, insufficient amounts of these gases may be available for
injection. FIG. 10 illustrates a process 300 for use in monitoring
when sufficient gas is available for injection. This process 300 is
based on the realization that, when instantaneous gas injection
rates fall to certain levels, the reduction of injection gas can
impact the efficiency of the artificial lift technique (e.g., gas
lift). Therefore, at any point, when current gas injection rates
fall to predefined low levels, the results of the analysis
determined by the hunting process/algorithm need to be protected by
restarting the interval to gather analysis of the BHP drawdown of
any particular Gas Injection Rate setpoint. The process 300 is a
sub routine that operates in parallel with the hunting
process/algorithm to protect the validity of the results of Bottom
Hole Pressure drawdown associated with any Gas injection Set point
in a defined interval.
[0051] As shown, the process (e.g., as implemented in the
controller) periodically obtains 302 a current gas injection rate.
The current gas injection rate may be a real-time reading of the
rate that gas is being injected at surface into the well. Such
current readings may be taken at user defined intervals. The
current gas injection rate is compared 304 to a minimum gas
injection rate setpoint or threshold. If the current gas injection
rate exceeds the minimum gas injection rate threshold or setpoint,
the hunting process 306 continues unabated until the next current
gas injection rate is read and compared to the threshold. If the
current gas injection rate falls below the defined
setpoint/threshold, the process 300 enters a gas injection rate
failure subroutine 308. At this time, the process stops the hunting
algorithm/process and monitors the current gas injection rate 310.
Such monitoring continues 312 until the available gas (e.g.,
current gas injection rate) exceeds the current gas injection
setpoint (e.g., as previously determined by the hunting algorithm).
Once the current gas injection rate is sufficient, the hunting
algorithm/process interval and BHP averages are reset 314 and the
gas injection continues at the last gas injection rate setpoint.
Stated otherwise, should the Current Gas injection rate fall below
the threshold, the data being averaged for the purpose of the
hunting algorithm during that interval is thrown out and the
hunting algorithm does not start a new interval until the current
gas injection rate reaches the current gas injection rate set
point. Once the current gas injection rate reaches the gas
injection set point a new interval is started and the normal
operation of the hunting algorithm commences.
[0052] Table 3 illustrates data for two intervals where a gas
injection rate falls below a predetermined minimum. In the
presented example the interval length is 24 hours with readings
taken every hour and a minimum gas injection threshold of 300
MCF.
TABLE-US-00003 TABLE 3 BHP AVG BHP GIR for Interval Interval Time
Setpoint GIR BHP interval Event Delta GIR ADJ 1 8:00 500 501 2000
2000 Start Of Interval 1 1 9:00 500 495 1999 1999.5 1 . . . . . . .
. . . . . . . . 1 5:00 500 521 1986 1986 1 6:00 500 523 1987 1986.5
1 7:59 500 524 1988 1987.5 End of -12.5 50 Interval 1 2 8:00 500
514 1990 1988.333 Start of Interval 2 2 9:00 550 525 1989 1989 2 .
. . . . . . . . . . . . . . 2 15:00 550 500 1988 1988 2 16:00 550
550 1986 1987 2 17:00 550 527 1985 1986.333 2 18:00 550 123 1998
1989.667 Enter MIN GIR FAIL 2 19:00 550 0 2000 2000 N\A 20:00 550 0
2001 2000.5 N\A 21:00 550 0 2002 2001.5 N\A 22:00 550 0 2003 2002.5
N\A 23:00 550 100 2004 2003.5 N\A 0:12 550 561 2004 2004 Exit Min
GIR Fail 2 0:12 550 551 2004 2004 Restart Interval 2 2 1:12 550 556
2003 2003.5 2 . . . . . . . . . . . . . . . 2 23:12 550 521 1993
1993 2 0:12 550 552 1994 1993.5 End of -10.5 -25 Interval 2
As set forth in Table 3, numerous readings are omitted for purposes
of presentation. Initially, Interval 1 starts at 8:00 with a GIR
Setpoint of 500 MCF and BHP of 2000 psi. Every hour (or other
sub-interval) the actual GIR is measured as is the bottom hole
pressure. Of note, the actual GIR may vary from the GIR Setpoint.
In this example, Interval 1 proceeds without the actual GIR falling
below the minimum gas injection threshold. At the end of Interval 1
at 7:59 (i.e., next day), the BHP average is calculated from all of
the readings, a BHP Delta is calculated and a GIR ADJ of +50 MCF is
made to the GIR setpoint. Thus, Interval 2 starts with a GIR
Setpoint of 550 MCF and a BHP Average of 1988.33. At 18:00, ten
hours into Interval 2, the actual GIR (available gas) drops to 123
MFC, which is below the minimum gas injection threshold of 300 MCF.
Thus, the process of FIG. 10 enters failure mode awaiting for
available gas to reach the setpoint for Interval 2 (550 MCF). At
0:12, the available gas exceed the setpoint and the hunting
algorithm restarts for a new 24 hour period. At the end of the new
Interval 2, the BHP Delta is calculated from the BHP recorded or
calculated at the start of new Interval 2 rather than the BHP
recorded at the start of the aborted Interval 2. Accordingly, the
gas injection rate adjustment (GIR ADJ) is calculated based on this
BHP Delta.
[0053] The foregoing description has been presented for purposes of
illustration and description. Furthermore, the description is not
intended to limit the disclosed embodiments to the forms disclosed
herein. Consequently, variations and modifications commensurate
with the above teachings, and skill and knowledge of the relevant
art, are within the scope of the present disclosure. The
embodiments described hereinabove are further intended to explain
best modes known of practicing the disclosed processes and to
enable others skilled in the art to utilize these processes in
such, or other embodiments and with various modifications required
by the particular application(s) or use(s) of the presented
disclosure. It is intended that the appended claims be construed to
include alternative embodiments to the extent permitted by the
prior art.
* * * * *